CN111963149A - Post-fracturing formation pressure calculation method considering stagnant ground fluid volume pressurization - Google Patents
Post-fracturing formation pressure calculation method considering stagnant ground fluid volume pressurization Download PDFInfo
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Abstract
The invention discloses a post-fracturing formation pressure solving method considering the pressure boost of stagnant ground liquid, which comprises the following steps: inputting geological parameters, engineering parameters and fracturing construction parameters of a target reservoir into a fracturing extension model, simulating to obtain stratum pressure change of the target reservoir in a fracturing construction process, selecting stratum pressure with the same amount of the liquid entering the ground and the liquid stagnating the target reservoir, and taking the stratum pressure as initial stratum pressure under the influence of pressurization of the liquid stagnating the ground; and inputting the initial formation pressure into a pressure diffusion model to obtain a decreasing change rule of the formation pressure after fracturing along with time, and further obtaining the formation pressure at any moment according to the decreasing change rule of the formation pressure along with time. The method realizes dynamic evaluation of the near-well formation pressure after fracturing.
Description
Technical Field
The invention belongs to the field of oil-gas-containing reservoir engineering, and particularly relates to a method for solving formation pressure in a flowback production period after fracturing, wherein the influence of the pressurization of stagnant liquid volume and the diffusion of pressure to the far end of a formation on the formation pressure is mainly considered.
Background
With the continuous decline of the quality of newly increased oil gas exploration reserves in China, the benefit of oil gas development is restricted by a plurality of low-yield wells. Meanwhile, horizontal wells and volume fracturing technologies at home and abroad are rapidly developed, and remarkable application effects are achieved in the development of low-permeability and unconventional oil and gas reservoirs. However, in reservoirs of different types and different physical properties, the stratum productivity has great difference under the condition of adopting different fracturing construction scales and modes, wherein the size and the change of the stratum pressure after fracturing have obvious influence on the stratum productivity, but the current stratum pressure after fracturing has limited acquisition means. Therefore, a method for determining the formation pressure after fracturing by considering the pressurization of the stagnant ground fluid is needed.
Disclosure of Invention
The invention provides a post-fracturing formation pressure obtaining method considering the stagnant ground fluid volume pressurization, aiming at the problems that the post-fracturing formation pressure changes, the influence factors are multiple, the rule is complex, the means for continuously obtaining the dynamic formation pressure is lack, and the like.
In order to solve the technical problems, the invention is realized by the following technical scheme:
a method of post-fracture formation pressure estimation with stagnant fluid volume pressurization considered, comprising:
inputting geological parameters, engineering parameters and fracturing construction parameters of a target reservoir into a fracturing extension model, simulating to obtain stratum pressure change of the target reservoir in a fracturing construction process, selecting stratum pressure with the same amount of the liquid entering the ground and the liquid stagnating the target reservoir, and taking the stratum pressure as initial stratum pressure under the influence of pressurization of the liquid stagnating the ground;
and inputting the initial formation pressure into a pressure diffusion model to obtain a decreasing change rule of the formation pressure after fracturing along with time, and further obtaining the formation pressure at any moment according to the decreasing change rule of the formation pressure along with time.
Further, the fracture propagation model is a multi-seam mode PKN model, and an expression of the multi-seam mode PKN model is as follows:
wherein:
in the formula: wmax(x) The maximum crack width m of the x point in the crack under the Newton liquid laminar flow condition;
p (x) is the pressure at the x point in the fracture, Pa; pc is fracture closure pressure, Pa;
mu is the viscosity of the fracturing fluid in the crack, Pa.s; e is Young's modulus, Pa; nu is Poisson's ratio and is dimensionless;
alpha is a coefficient related to the displacement and is dimensionless; h is the crack height, m; l is the half-length of the crack, m;
q is the displacement, m3Min; a is the area of the crack, m2；DfIs a fracture plane fractal dimension without dimension;
c is the comprehensive fluid loss coefficient,
erfc (x) is the error compensation function for x.
Further, the expression of the pressure diffusion model is as follows:
P(t)＝Pe+(Pb0-Pe)e-at
in the formula: p (t) is post-fracture dynamic formation pressure; peIs the original formation pressure; pb0Pressurizing the near-well formation initial pressure under the influence of the stagnant fluid; a is a pressure diffusion rate index; t is time.
Further, the geological parameters include: depth in the middle of the reservoir, reservoir thickness, shale content, porosity, permeability, and oil (gas) saturation.
Further, the engineering parameters include: formation pressure, Young's modulus, Poisson's ratio, Biot coefficient, vertical principal stress, maximum horizontal principal stress, and minimum horizontal principal stress.
Further, the fracture construction parameters include: average displacement, fracturing time, fracturing fluid viscosity, fluid loss coefficient, total amount of proppant and fluid slugging amount.
Further, the diffusion coefficient in the pressure diffusion model is obtained through the fracture swept volume and the permeability of the reservoir matrix.
Furthermore, the diffusion coefficient in the pressure diffusion model is subjected to scale correction by utilizing pressure test data of actual fracturing construction.
Compared with the prior art, the invention has at least the following beneficial effects: the existing method for acquiring the stratum pressure after fracturing is mainly calculated through fracturing construction data, wherein the most common method is to close a well after fracturing and measure the pressure change of the well mouth, and the stratum pressure is calculated through the pressure of the well mouth and the pressure of a liquid column of a shaft. Compared with this type of technology, the present invention has at least three advantages: 1. formation pressure may be calculated in wells that are not tested for post-pressure drawdown; 2. the dynamic change condition of the formation pressure can be simulated and calculated; 3. meanwhile, the distribution change of the fluid quantity of the dead space is considered, and the pressure change of the stratum at different radial depths of the stratum can be obtained theoretically. According to the invention, the stratum pressure information corresponding to the amount of the stagnant stratum at the end of flowback is obtained by simulating the stratum pressure change information obtained by fracturing crack expansion, and then a near-well stratum pressure attenuation model (namely a pressure diffusion model) generated by diffusing the stagnant fracturing fluid to the stratum is introduced, so that the dynamic calculation of the near-well stratum pressure after flowback is realized.
In order to make the aforementioned and other objects, features and advantages of the present invention comprehensible, preferred embodiments accompanied with figures are described in detail below.
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In order to more clearly illustrate the technical solutions in the embodiments of the present invention, the drawings used in the description of the embodiments will be briefly introduced below, and it is obvious that the drawings in the following description are some embodiments of the present invention, and it is obvious for those skilled in the art that other drawings can be obtained according to the drawings without creative efforts.
FIG. 1 is a schematic diagram of a method of formation pressure determination in accordance with the present invention that takes into account slugging fluid pressurization;
FIG. 2 is a schematic diagram of the parameter input of the PKN model based on the multislice mode according to the present invention;
FIG. 3 is a schematic diagram of the near-well formation pressure simulation calculation condition of the fracturing pumping period of the PKN model based on the multi-fracture mode.
Detailed Description
To make the objects, technical solutions and advantages of the embodiments of the present invention clearer, the technical solutions of the present invention will be clearly and completely described below with reference to the accompanying drawings, and it is apparent that the described embodiments are some, but not all embodiments of the present invention. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present invention.
The logging information can provide relatively economic and continuous quantitative evaluation results for reservoir geological parameters and engineering parameter evaluation, and can also be used for developing fracturing fracture expansion simulation based on the relatively economic and continuous quantitative evaluation results, and the formation pressure in the fracturing process can be obtained through a model in a 2D fracturing fracture expansion model (such as a PKN model in a multi-fracture mode) which can be solved by analysis. The method provides possibility for obtaining the formation pressure under the condition that the amount of the liquid stagnated in the production stage is known after fracturing.
The invention aims to solve the problem of calculating the formation pressure which influences the productivity of the fractured formation. The invention provides a method for obtaining stratum pressure at the initial stage after fracturing by considering the pressurization effect of stagnant ground liquid, which utilizes logging response data to evaluate reservoir geology and engineering parameters so as to develop fracturing crack expansion simulation, simulates the fracturing construction process until the liquid quantity entering the ground reaches the acquired stagnant ground liquid quantity, considers that the stratum pressure obtained by simulation calculation is close to the stratum pressure caused by the pressurization of the stagnant ground liquid quantity so as to develop stratum pressure attenuation correction along with time, and utilizes an actual data to scale a whole model so as to realize the stratum pressure prediction under the condition of known stagnant ground liquid quantity in the fracturing flowback production period.
In one embodiment of the present invention, a method for determining a post-fracturing formation pressure in consideration of a hydraulic stagnation amount includes:
firstly, referring to fig. 1, 2 and 3, inputting geological parameters, engineering parameters and fracturing construction parameters of a target reservoir into a fracturing extension model, simulating to obtain stratum pressure change of the target reservoir in the fracturing construction process (for example, a curve a in fig. 1, the curve a comprises change indication of near-well stratum pressure in fracturing and a later shut-in state, an ascending section of the curve is near-well stratum pressure change in a pumping stage, a descending section is stratum pressure attenuation in a pumping-stopping stage), simulating to obtain fracture length and width change of the target reservoir in the fracturing construction process, selecting stratum pressure with the same size of an earth-entering liquid amount as an earth-stagnation liquid amount of the target reservoir, and using the stratum pressure as initial stratum pressure under the influence of the pressure increase of the earth-stagnation liquid amount; that is, simulating a fracturing construction process until the amount of the liquid entering the ground is the same as the amount of the liquid stagnated in the target reservoir, and considering that the formation pressure obtained by simulation calculation is similar to the formation pressure caused by pressurization of the amount of the liquid stagnated in the ground (containing the same amount of the fracturing liquid in the formation);
in this embodiment, the geological parameters and engineering parameters of the target reservoir are calculated based on the logging information, and specifically, the geological parameters include: depth in the middle of the reservoir, reservoir thickness, shale content, porosity, permeability and oil (gas) saturation; the engineering parameters include: formation pressure, Young's modulus, Poisson's ratio, Biot coefficient, vertical principal stress, maximum horizontal principal stress, and minimum horizontal principal stress;
in this embodiment, the fracturing construction parameters include: average displacement, fracturing time, fracturing fluid viscosity, fluid loss coefficient, total amount of proppant and fluid stagnation;
in this embodiment, the fracture propagation model is a multi-gap PKN model, and the expression of the multi-gap PKN model is as follows:
for the seam length parameter, a Katt model seam surface area formula is usually introduced during solving, and the solution is realized by iteration, wherein the formula is as follows:
L＝A/2H
or, in the solving process of the fracture expansion model, the general condition in the fracturing of the compact reservoir is considered, namely the existence of the fracture in a fracture network form with certain complexity is considered, the solving method is improved, and the fracture network plane fractal dimension D is introducedfOrder:
taking value according to fractal dimension of general complex plane graph DfTaking 1.12-1.18;
in the formula: wmax(x) The maximum crack width m of the x point in the crack under the Newton liquid laminar flow condition;
p (x) is the pressure at the x point in the fracture, Pa; pc is fracture closure pressure, Pa;
mu is the viscosity of the fracturing fluid in the crack, Pa.s; e is Young's modulus, Pa; nu is Poisson's ratio and is dimensionless;
alpha is a coefficient related to the displacement and is dimensionless; h is the crack height, m; l is the half-length of the crack, m;
q is the displacement, m3Min; a is the area of the crack, m2；DfIs a fracture plane fractal dimension without dimension;
c is the comprehensive fluid loss coefficient,
erfc (x) is the error compensation function for x.
Then, inputting the initial formation pressure into a pressure diffusion model to obtain a decreasing change rule of the formation pressure after fracturing along with time (curve b in fig. 1, curve b is the change of the formation pressure of the near well after the flowback is finished), and further obtaining the formation pressure at any moment according to the decreasing change rule of the formation pressure along with time; wherein, the diffusion coefficient in the pressure diffusion model is obtained through the fracturing swept volume and the permeability of the reservoir matrix;
in this embodiment, the expression of the pressure diffusion model is:
P(t)＝Pe+(Pb0-Pe)e-at
in the formula: p (t) is post-fracture dynamic formation pressure; peIs the original formation pressure; p (t) is post-fracture dynamic formation pressure; peIs the original formation pressure; pb0Pressurizing the near-well formation initial pressure under the influence of the stagnant fluid; a is a pressure diffusion rate index; t is time;
in the embodiment, the fracture swept volume (SRV) is estimated according to an elliptic cylinder model based on the maximum half length of the fracture and the horizontal stress difference;
in the present embodiment, in an area with sufficient partial data, the diffusion coefficient in the pressure diffusion model is calibrated by using measured data obtained by fracturing (i.e., pressure test data of actual fracturing), and the calibration method is to obtain the time (unit: hour) when the attenuation amplitude of the measured formation pressure reaches 95%, and then use the following empirical formula a ═ 0.777 · T ═-1.05And the a value is given, so that the calculation accuracy of the model in other wells and other reservoirs in the region is improved.
Curve c in fig. 1 is the pressure change at the flow-back stage after pressing; in fig. 1, the time axis is a relative dimension.
The principle of the invention is as follows: the invention relates to a near-well stratum pressure simulation calculation method which is adopted for obtaining the near-well stratum pressure condition under a specific fluid stagnation amount after a compact reservoir is fractured and drained. First, it is necessary to implement a fracturing fracture propagation simulation based on the logging reservoir parameters and the fracturing construction parameters so as to obtain the formation pressures corresponding to different quantities of fluid entering the ground during the fracturing, specifically, as described aboveThe content of (a); secondly, an equivalent mode is adopted, the near-well formation pressure is equal when the ground liquid amount is equal to the stagnant ground liquid amount, and therefore the near-well formation pressure P at the end of the flow-back is obtainedb0(ii) a Thirdly, the near-well fracturing fluid is continuously expanded towards the stratum during the soaking period, the near-well stratum pressure is gradually attenuated until the near-well stratum pressure is consistent with the pressure of the undisturbed stratum, and the near-well stratum pressure attenuation amplitude and the near-well stratum pressure value P (t) of the corresponding time during the soaking period are obtained by using a pressure diffusion model formula according to the soaking time (closing the well after flowing back); finally, a near-well formation pressure sequence is predicted. During the period, the pressure diffusion model is scaled through actual data so as to improve the accuracy of obtaining the formation pressure.
Example (b):
taking a certain well of XX stratum in CQ oil field LJZ area as an example, the method comprises the following steps:
step 1) carrying out fracture expansion simulation based on an improved multi-fracture mode PKN model according to reservoir and engineering parameters (shown in figure 2) evaluated by logging and combined with fracture construction parameters to obtain formation pressure, maximum half-fracture length and maximum fracture width information (shown in figure 3) corresponding to different quantities of liquid entering the ground in the fracturing process;
step 2) the amount of the residual ground liquid after the combined flowback is 50m3According to FIG. 3, the amount of the obtained ground liquid was 50m3The near-well formation pressure is 29.00Mpa, which is taken as the initial formation pressure P after the near-well fracturing at the end of the flowbackb0；
Step 3) combining the original formation pressure P according to the soaking (shut-in after flowback) time of 50he27.15MPa and the regional experience a is 0.045, and the pressure attenuation amplitude of the near-well stratum during the soaking period and the dynamic stratum pressure value P (t) after the near-well fracturing corresponding to the time are obtained by using a formula 6 and are 27.35 MPa;
the actual measurement pressure of the well mouth after the well is shut in is 3.75Mpa, and the density of the fluid in the well bore is 1.13g/cm3The depth of the formation is 2125m, the reverse calculated near-well formation pressure is 23.60Mpa, and the error is 0.28%.
The invention discloses a method for solving formation pressure at the initial stage after fracturing by considering the fluid stagnation supercharging effect, belonging to the field of hydrocarbon-containing reservoir evaluation. The method is based on a simulated fracture expansion model, and comprehensively obtains the formation pressure and the change condition thereof after fracturing fluid is returned by assuming that the near-well formation pressure is similar when the same volume of foreign fluid (including carried proppant) exists in the formation and considering the near-well formation pressure decreasing effect caused by the diffusion of the near-well formation fluid to the far-end formation along with the change of time (figure 1). The stratum pressure calculated by the method can be used for obtaining stratum dynamic productivity, avoids oil testing risks, and has great practical significance.
Finally, it should be noted that: although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art will understand that: any person skilled in the art can modify or easily conceive the technical solutions described in the foregoing embodiments or equivalent substitutes for some technical features within the technical scope of the present disclosure; such modifications, changes or substitutions do not depart from the spirit and scope of the embodiments of the present invention, and they should be construed as being included therein. Therefore, the protection scope of the present invention shall be subject to the protection scope of the claims.
Claims (8)
1. A method for determining a post-fracturing formation pressure by taking into account a fluid stagnation amount pressurization, comprising:
inputting geological parameters, engineering parameters and fracturing construction parameters of a target reservoir into a fracturing extension model, simulating to obtain stratum pressure change of the target reservoir in a fracturing construction process, selecting stratum pressure with the same amount of the liquid entering the ground and the liquid stagnating the target reservoir, and taking the stratum pressure as initial stratum pressure under the influence of pressurization of the liquid stagnating the ground;
and inputting the initial formation pressure into a pressure diffusion model to obtain a decreasing change rule of the formation pressure after fracturing along with time, and further obtaining the formation pressure at any moment according to the decreasing change rule of the formation pressure along with time.
2. The method of claim 1, wherein the fracture propagation model is a multi-fracture mode PKN model.
3. The method of claim 1, wherein the pressure diffusion model is expressed as:
P(t)＝Pe+(Pb0-Pe)e-at
in the formula: p (t) is post-fracture dynamic formation pressure; peIs the original formation pressure; pb0Pressurizing the near-well formation initial pressure under the influence of the stagnant fluid; a is a pressure diffusion rate index; t is time.
4. The method of claim 1, wherein the geological parameters comprise: depth in the middle of the reservoir, reservoir thickness, shale content, porosity, permeability, and oil (gas) saturation.
5. The method of claim 1, wherein the engineering parameters comprise: formation pressure, Young's modulus, Poisson's ratio, Biot coefficient, vertical principal stress, maximum horizontal principal stress, and minimum horizontal principal stress.
6. The method of claim 1, wherein the fracture construction parameters comprise: average displacement, fracturing time, fracturing fluid viscosity, fluid loss coefficient, total amount of proppant and fluid slugging amount.
7. The method of claim 1, wherein the diffusion coefficient in the pressure diffusion model is determined by fracture swept volume and reservoir matrix permeability.
8. The method for determining the formation pressure after fracturing considering the pressure increase of the stagnant ground fluid amount as claimed in claim 7, wherein the diffusion coefficient in the pressure diffusion model is calibrated by using pressure test data of actual fracturing construction.
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